System for coating tubing encapsulated cable for insertion into coil tubing

ABSTRACT

Tubing encapsulated cable consists of one or more electrical conductors and possibly one or more fiber optic cables sheathed in a corrosion resistant metallic alloy. However, pumping during the installation of tubing encapsulated cable is required to overcome the capstan effect of the tubing encapsulated cable inside the coil tubing as the tubing encapsulated cable travels through the coiled up wraps of coil tubing. One way to overcome the capstan effect is to reduce the contact between the coil tubing and the tubing encapsulated cable by installing standoffs along the length of the tubing encapsulated cable. Other additional friction between inner surface of the coil tubing and the tubing encapsulated cable that occurs during the installation of the tubing encapsulated cable and the inner surface of the coil tubing may be reduced by adding standoffs along the length of the coil tubing. In some instances the standoffs may be dissolvable so that the standoffs do not impede fluid flow through the interior of the coil tubing during intervention work.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Patent Application No. 61/915,897 that was filed on Dec. 13, 2013.

BACKGROUND

Tubing encapsulated cable can be difficult to insert into coil tubing. Tubing encapsulated cable typically consists of one or more electrical conductors, a fiber optic cable, and possibly other cables or lines sheathed in a corrosion resistant alloy such as 316 stainless steel or a fiber reinforced composite sheath. The smooth outside surface and relatively small diameter of tubing encapsulated cable are desirable attributes for well intervention work because the relatively smooth surface may be more resistant to chemical attack than braided wire. Additionally, the relatively smooth surface and small diameter (0.125″-0.250″) minimizes viscous drag exerted upon the cable as fluids pumped through the coil tubing in the course of intervention operations pass by the cable. Because there is little drag exerted on the tube wire by the fluid, conventional pumping operations used to install braided wireline into coil tubing are not sufficient to install tubing encapsulated cable. Pumping fluid through the coil tubing during the installation of tubing encapsulated cable is required to assist in overcoming the capstan effect, caused by the friction between the coil tubing and the tubing encapsulated cable as the tubing encapsulated cable travels through the wound coil tubing.

There are numerous techniques that may be utilized to install tubing encapsulated cable into a long tubular member such as coil tubing. Such as hanging the coil into the well, to the extent that the well section is relatively vertical, in order to allow the somewhat reliable force of gravity to pull the tubing encapsulated cable downward into the interior of the coil tubing. Another commonly known technique involves spooling out the coil tubing along a roadway, installing a rope, cable, or equivalent and using the rope or cable in a manner similar to that of an electrician's fish tape to pull the tubing encapsulated cable into the coil tubing. In these instances fluid may or may not be pumped into the coil tubing while inserting the tubing encapsulated cable. Inserting the tubing encapsulated cable into coil tubing as described above can be an expensive operation.

Another currently utilized method of installing tubing encapsulated cable into coil tubing is to attach a plug to an end of the tubing encapsulated cable. The end of the tubing encapsulated cable is then inserted into the coil tubing and fluid is then pumped through the coil tubing. The fluid exerts force on the plug and the plug will then pull the tubing encapsulated cable through the coil tubing as the plug is pumped through the coil tubing.

SUMMARY

One solution to the problem of running a long tubing encapsulated cable into coil tubing is to coat the tubing encapsulated cable with a removable coating. The coating would cause the tubing encapsulated cable to have a greater surface area than uncoated tubing encapsulated cable. The increased surface area would allow the tubing encapsulated cable to be pumped into coil tubing using the same techniques that are currently employed to due to higher friction between the fluid and the now larger surface area of the tubing encapsulated cable cause d by the higher viscous shear rate between the fluid and cable coating as fluid is pumped through the coil tubing along it the length of the tubing encapsulated cable. Additionally the coating material may incorporate a relatively rough or adhesive surface to further increase the viscous shear rate between the fluid and cable coating.

It is common to coat tubing encapsulated cable with a layer of polypropylene up to 0.25 inches thick to aid in monitoring the well bore. The polypropylene is applied to provide crush and pinch protection when the tubing encapsulated cable is installed in a wellbore.

Once the tubing encapsulated cable is installed inside coil tubing, it is not desirable to have a coating present because the coating creates additional viscous drag when fluids are pumped through the coil tubing during well intervention work. After the insertion of the tubing encapsulated cable into the coil tubing, the coating is removed by chemical or thermal means or a combination there of. Unfortunately the current polypropylene coating, once applied, is difficult, if not impossible, to be completely removed from the tubing encapsulated cable after the tubing encapsulated cable is installed in the coil tubing.

In an embodiment of the present invention the coating may consist of a wax, polyglycolic acid (PGA, polyglycolide), poly vinyl acetate (PVA, PVAc, polyethyl ethanoate), a low grade polymer, starch, or some other material that could be easily stripped from the tubing encapsulated cable by immersing the tubing encapsulated cable, and the coating, in water or other suitable solvent. Water soluble plastics such as PGA and PVA are commonly available. PGA is utilized for frac balls and other applications in the oilfield. PVA is utilized to make plastic bags for use in hospitals and for pouches that contain dishwasher detergent. Typically the coating is applied to enlarge the diameter of the tubing encapsulated cable to at least 0.375 inches although in some cases the diameter of the tubing encapsulated cable may be enlarged to 0.4375 inches or more.

In some instances it may be desirable to heat the tubing encapsulated cable and the coating to aid the solvent in the removal of the coating. In the case of wax, low grade polymers, or other heat sensitive coatings, it may only be necessary to expose the coating to elevated temperatures to remove the coating. The heat could be applied by heating the fluid in coil tubing. The coating could also be self-degrading over time or even be biodegradable.

In an alternative embodiment of this invention, the coating may not be continuous in length. It may be desirable to coat only short sections of the tubing encapsulated cable to create periodic undulations in the diameter of the tubing encapsulated cable. These undulations could be spherical, rectangular, or any desired shape. Additionally the undulations could be of any length or of variable length. For instance an undulation could be 1 meter in length separated from the adjacent undulation by a fraction of a meter, 1 meter, or several meters. These discrete undulations may also reduce the friction associated with the capstan effect.

These undulations tend to provide a standoff that minimizes the contact between the coil tubing and the tubing encapsulated cable. By minimizing the contact between the coil tubing and the tubing encapsulated cable electrolytic corrosion between the coil tubing and the tubing encapsulated cable is reduced.

In one embodiment a tubing encapsulated cable has standoffs attached to the tubing encapsulated cable every few feet. Typically the distance between the standoffs will be a function of the diameter of the standoff and the rigidity of the tubing encapsulated cable. A comparatively rigid tubing encapsulated cable may have small diameter standoffs relatively close to one another or large diameter standoffs that may be spaced farther apart. In either case the object is to minimize the contact between the coil tubing and the tubing encapsulated cable. The standoffs may be made of any material, and may be formed as a part of the tubing encapsulated cable. In other instances the standoffs may be threaded onto the tubing encapsulated cable in the manner that beads are strung on a string and then fixed in place by adhesives, screws or other fastening means. In some instances the standoffs may be manufactured in pieces, such as halves, that are then placed on the tubing encapsulated cable and then fixed in place by adhesives, screws or other fastening means. In other instances the standoffs may be formed as a part of the tubing encapsulated cable during the manufacture of the tubing encapsulated cable.

In certain instances it may not be desirable to have standoffs on the tubing encapsulated cable due to the drag that may be exerted on the tubing encapsulated cable via the standoffs by fluid as fluid is pumped through the coil tubing. In this instance it may be desirable to manufacture the standoffs out of a dissolvable or erodible material, such as polyglycolic acid. A standoff consisting of an erodible or dissolvable material would provide separation between the coil tubing and the tubing encapsulated cable during the installation of the tubing encapsulated cable into the coil tubing and until such time as the appropriate media was introduced into the coil tubing to cause the standoffs to erode or dissolve.

In another embodiment the standoffs may be directional such that the standoffs present a surface have high drag through a fluid when the fluid is moving past the standoff in a particular direction and the have a lower drag through the fluid when the fluid is moving past the standoff in a different direction.

Typically the tubing encapsulated cable may be formed around an inner core that may consist of one or more electrical conductors or fiber optic cables or some combination of electrical conductors and fiber optic cables. When the tubing encapsulated cable is carbon fiber composite tubing it may be formed around an inner core by a continuous braiding process where independent strands of fiber are spirally braided together to form a tube that encapsulates the inner core. In many instances after the carbon fiber composite tubing is formed around the inner core the carbon fiber outer sheath may be impregnated with an epoxy or other binder. The epoxy tends to give the carbon fiber outer sheath a smooth surface reducing viscous drag when compared to a tubing encapsulated cable having a stainless steel outer sheath. Such a tube may be created in any length desired but preferably of such a length as to match the length of the coil tubing that the carbon fiber wrapped core will be installed in.

In an alternative embodiment an inner core such as a communications line or a cable may be laid over the top of a flat length of pre-woven carbon fiber such a length of carbon fiber cloth. The pre-woven carbon fiber may then by rolled into a tubular or other shape to encapsulate the inner core. The now adjoining edges of the pre-woven carbon fiber may then be attached by various means including sewing the edges together, by using an adhesive such as an epoxy to bond the edges of the pre-woven cloth together, or by impregnating the carbon fiber outer sheath with epoxy or other binder or adhesive.

In another embodiment the fiber encapsulated cable for downhole use is installed in a coil tubing. A conductor may be at least a first conductor and a second conductor. The first conductor may be an electrical conductor and the second conductor may be an optical conductor. In certain instances the conductor may have a coating and that coating may be an insulator. A fiber sheath wraps around the conductor and the fiber sheath typically has a low coefficient of friction. The fiber sheath may be resin impregnated. The fiber sheath may be carbon fiber, fiberglass, or any other fiber known in the industry. A filler may separate the conductor from the fiber sheath. In certain instances the filler may be electrically conductive or electrically insulative. Typically the fiber encapsulated cable is pulled through the coil tubing in order to insert the fiber encapsulated cable into the coil tubing without pumping a fluid through the coil tubing.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts an embodiment of a tubing encapsulated cable having standoffs applied along the length of a tubing encapsulated cable.

FIG. 2 depicts a standoff that has been fixed to the tubing encapsulated cable.

FIG. 3 depicts a side view of the standoff of FIG. 2.

FIG. 4 depicts a closeup of the embodiment of FIG. 1 showing a single standoff on tubing encapsulated cable.

FIG. 5 depicts a single standoff on tubing encapsulated cable where the tubing encapsulated cable has a first fiber optic conductor and a second fiber optic conductor.

FIG. 6 depicts the standoffs spaced along the length of a tubing encapsulated cable.

FIG. 7 depicts a directional standoff.

FIG. 8 depicts a low drag standoff.

DETAILED DESCRIPTION

The description that follows includes exemplary apparatus, methods, techniques, or instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details.

FIG. 1 depicts an embodiment of the present invention where a tubing encapsulated cable 10 has standoffs 12 along the length of the tubing encapsulated cable 10. Each of the standoffs 12 are spaced apart at some distance 14 from the adjacent standoff 12. The distance 14 may vary between standoffs placed along the tubing encapsulated cable 10 depending upon variables such as the rigidity of the tubing encapsulated cable 10, the diameter 16 of the standoff, and the needs of the user. As required the standoff may be made of a dissolvable or an erodible material such as polyglycolic acid. In some instances each standoff 12 may be molded in place by injection molding, resin transfer molding, or other similar methods.

FIG. 2 depicts a standoff 20 that has been fixed to a tubing encapsulated cable 22. The standoff 20 has a first half 24 and a second half 26. The first half 24 and the second half 26 may be placed on either side of the tubing encapsulated cable 22 and screws or bolts are used to hold the two halves against the tubing encapsulated cable 22 and each other. The assembled standoff 20 may be held in place along the tubing encapsulated cable 22 by friction, adhesives, or any other means known in the industry.

FIG. 3 is a side view of the standoff 20 of FIG. 2. The first half 24 has at least one throughbore 30 for a screw 34, bolt, pin, or other attachment means to pass through the first half 24. Typically each throughbore 30 has a recessed portion 32 to prevent the screw 34 from protruding past the outer diameter of the standoff where it could potentially strike or be struck by an object in the coil tubing. The second half 26 of the standoff 20 has a hole 36. The hole 36 may be threaded or may be of a smaller diameter than the screw 34 such that a self-tapping screw, extending from throughbore 30 may be screwed into the hole 36 to retain both the first half 24 and the second half 26 against tubing encapsulated cable 38. Generally, the first half 24 has a first indentation 40 and the second half 26 has an indentation 42 to receive the tubing encapsulated cable 38 although in certain instances only one of the first half 24 and second half 26 may have an indentation for receiving the tubing encapsulated cable 38. The first indentation 40 and the second indentation 42 may be slightly smaller than the diameter of the tubing encapsulated cable 38 to facilitate holding the standoff 20 in place on the tubing encapsulated cable 38 due to the high friction between the tubing encapsulated cable 38 and the standoff 20 although in some instances an adhesive may also be used.

FIG. 4 depicts a closeup of the embodiment of FIG. 1 showing a single standoff 12 on tubing encapsulated cable 10. In this case tubing encapsulated cable 10 consists of a single electrical conductor 50 surrounded by a pliable material 52, where the pliable material 52 may be an electrical insulator such as a carbon fiber matrix comprised of strands of carbon fiber and/or carbon nano-tubes in a polymer matrix that bonds the matrix together although the pliable material could be a simple polymer, plastic, or other insulator. The pliable material is then encased in an external armor 54 such as stainless steel or wound carbon fiber. The standoff 12 has a diameter 56 while the tubing encapsulated cable 10 has a diameter 58. The tubing encapsulatd cable 10 may have a coating applied to the tubing encapsulated cable 10 such that the diameter 58 of the tubing encapsulated cable 10 may be at least 0.375 inches and in some instances may be increased to 0.4375 inches or more. The diameter 56 of the standoff 12 will vary depending upon factors such as the diameter of the tubing encapsulated cable 10, the rigidity or strength of the tubing encapsulated cable 10, and the radius of any turns that the tubing encapsulated cable 10 has to make while being inserted in to the coil tubing (not shown).

FIG. 5 depicts an alternative embodiment of the tubing encapsulated cable of FIG. 1. FIG. 5 shows a single standoff 62 on tubing encapsulated cable 60. In this case tubing encapsulated cable 60 consists of a first fiber optic conductor 64 and a second fiber optic conductor 66. The first fiber optic conductor 64 may be coated or otherwise surrounded by an optical coating 68 to enhance the transmission of light through the fiber optic conductor 64. The second fiber optic conductor 66 may also be coated or otherwise surrounded by an optical coating 70 to enhance the transmission of light through the fiber optic conductor 64. The fiber optic cables may be surrounded by a pliable material 72 such as a carbon fiber matrix comprised of strands of carbon fiber and/or carbon nano-tubes in a polymer matrix that bonds the matrix together although the pliable material 72 could be a simple polymer, plastic, or other insulator. In some instances a fiber optic conductor, such as first fiber optic conductor 64 or second fiber optic conductor 66, may be replaced with an electrical conductor. In certain cases such as when at least one of the conductors is an electrical conductor the pliable material may include an electrically conductive material. Typically the pliable material 72 may then be encased in an external armor 74 such as stainless steel, wound carbon fiber, or a plastic coating such as a thermoplastic. In some instances, depending upon the coating used, the coating may then be formed into standoffs 62. For instance should a thermoplastic be used as the coating, the coating may be extruded over the tubing encapsulated cable, in some instances over the external armor although typically in place of the armor, and then shaped into standoffs 62 by rollers or other similar methods while the extruded thermoplastic is still hot. In other instances the standoffs may be formed by dissolving a portion of the coating to leave a standoff formed between the areas dissolved away.

FIG. 6 depicts an alternative embodiment of the present invention where the standoffs 100 are spaced along the length of a tubing encapsulated cable 102. In this embodiment each standoff 100 is shaped to reduce the drag exerted on the standoff 100 by the fluid (not shown) as the fluid passes the standoff 100 in a particular direction while increasing the drag exerted on the standoff 100 as the fluid passes the standoff in the opposite direction. A directional coating may also be used, by itself or in addition to a directional standoff, where the directional coating may be a micro fiber or filament that resist fluid flow in a single direction.

An example of such drag reduction or increase is depicted in FIG. 7 where when fluid flow is in the direction as shown by arrows 104 the fluid tends to exert an increased amount of drag on surface 106 of standoff 100. The increased drag may be desired such as when the tubing encapsulated cable 103 is being inserted into coil tubing 108. However when the fluid flow is in the direction as shown by arrows 110 the fluid tends to exert a decreased amount of drag on angled surface 112. The decreased drag may be desired when fluid is being pumped through the coil tubing 108 for coil tubing interventions and movement of the tubing encapsulated cable 103 may not be desirable. While surface 106 is shown as being flat any surface that tends to increase drag may be used. Such surfaces include flat, concave, or a hollow interior of the standoff 100 where the interior is subject to eh fluid flow. Similarly, the angled surface 112 does not need to be a single angle and could be parabolic, multi-faceted, or any surface to decrease the drag.

As depicted in FIG. 8, in other embodiments both the upstream surface 120 and the downstream surface 122 of the standoff 126 may be angled so that drag on the standoff 126 and thus the tubing encapsulated cable 128 will be reduced regardless o the direction of fluid flow through the coil tubing 124.

In certain embodiments the standoffs, such as standoff 126 in FIG. 8, may be constructed of a dissolvable or erodible material such as polyglycolic acid. A dissolvable standoff may be desirable to maximize potential fluid flow through the coil tubing after the tubing encapsulated cable 128 is inserted in the coil tubing 124. In other instances the standoff may be an inert material to minimize potential corrosion of the coil tubing while the standoff is in contact with the coil tubing.

The methods and materials described as being used in a particular embodiment may be used in any other embodiment. While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible.

Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter. 

What is claimed is:
 1. A tool for downhole use comprising: a coil tubing, a tubing encapsulated cable, wherein the tubing encapsulated cable includes at least two standoffs, wherein the standoffs are spaced along the tubing encapsulated cable.
 2. The tool for downhole use of claim 1 wherein, the at least two standoffs are dissolvable.
 3. The tool for downhole use of claim 1 wherein, the at least two standoffs are erodable.
 4. The tool for downhole use of claim 1 wherein, the at least two standoffs are non-metallic.
 5. The tool for downhole use of claim 1 wherein, the at least two standoffs have a first part and a second part.
 6. The tool for downhole use of claim 1 wherein, the standoff first part and the standoff second part are held in place against each other by at least one screw.
 7. The tool for downhole use of claim 1 wherein, the standoff first part and the standoff second part are held in place against each other by an adhesive.
 8. The tool for downhole use of claim 1 wherein, the standoff is fixed in place along the tubing encapsulated cable.
 9. The tool for downhole use of claim 1 wherein, the standoff is fixed in place along the tubing encapsulated cable by friction.
 10. The tool for downhole use of claim 1 wherein, the standoff is fixed in place along the tubing encapsulated cable by an adhesive.
 11. Method of installing a tool in a coil tubing comprising, attaching a standoff to a tubing encapsulated cable, wherein the tubing encapsulated cable has a first end and a second end, inserting the first end into a coil tubing, minimizing contact between the tubing encapsulated cable and the coil tubing, moving the tubing encapsulated cable into the coil tubing.
 12. The method of installing a tool in a coil tubing of claim 11 wherein, the tubing encapsulated cable is drawn into the coil tubing by pumping.
 13. The method of installing a tool in a coil tubing of claim 11 wherein, the tubing encapsulated cable is drawn into the coil tubing by pulling.
 14. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is dissolvable.
 15. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is erodable.
 16. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is non-metallic.
 17. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff has a first part and a second part.
 18. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff first part and the standoff second part are held in place against each other by at least one screw.
 19. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff first part and the standoff second part are held in place against each other by an adhesive.
 20. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is fixed in place along the tubing encapsulated cable.
 21. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is fixed in place along the tubing encapsulated cable by friction.
 22. The method of installing a tool in a coil tubing of claim 11 wherein, the standoff is fixed in place along the tubing encapsulated cable by an adhesive.
 23. A tool for downhole use comprising: a coil tubing, a tubing encapsulated cable, a coating on the tubing encapsulated cable, wherein the diameter of the coating is at least 0.375 inches.
 24. The tool for downhole use of claim 23 wherein, the diameter of the coating is at least 0.4375 inches.
 25. The tool for downhole use of claim 23 wherein, the coating is a dissolvable material.
 26. The tool for downhole use of claim 23 wherein, the coating is an erodible material.
 27. The tool for downhole use of claim 23 wherein, the coating is a non-metallic material.
 28. A tool for downhole use comprising: a coil tubing, a tubing encapsulated cable, an at least two standoffs, wherein the diameter of the at least two standoffs is at least 0.375 inches.
 29. The tool for downhole use of claim 28 wherein, the diameter of the standoffs is at least 0.4375 inches.
 30. The tool for downhole use of claim 28 wherein, the at least two standoffs are erodable.
 31. The tool for downhole use of claim 28 wherein, the at least two standoffs are non-metallic.
 32. The tool for downhole use of claim 28 wherein, the at least two standoffs have a first part and a second part.
 33. The tool for downhole use of claim 28 wherein, the standoff first part and the standoff second part are held in place against each other by at least one screw.
 34. The tool for downhole use of claim 28 wherein, the standoff first part and the standoff second part are held in place against each other by an adhesive.
 35. The tool for downhole use of claim 28 wherein, the standoff is fixed in place along the tubing encapsulated cable.
 36. The tool for downhole use of claim 28 wherein, the standoff is fixed in place along the tubing encapsulated cable by friction.
 37. The tool for downhole use of claim 28 wherein, the standoff is fixed in place along the tubing encapsulated cable by an adhesive.
 38. The tool for downhole use of claim 28 wherein, the standoff is molded in place along the tubing encapsulated cable.
 39. The tool for downhole use of claim 28 wherein, a portion of the coating is removed to form standoffs along the tubing encapsulated cable.
 40. The tool for downhole use of claim 28 wherein, a portion of the coating is thermally extruded.
 41. The tool for downhole use of claim 40 wherein, the thermally extruded coating is shaped into standoffs. 